Hydraulic fracturing for stimulation of conventional reservoirs comprises the injection of a high viscosity fracturing fluid at high flow rate to open and then propagate a bi-wing tensile fracture in the formation. With the exception of the near-wellbore region, where a complex state of stress might develop, it is expected that this fracture will propagate normal to the far-field least compressive stress. The length of this tensile fracture can attain several hundred meters during a fracturing treatment of several hours. The fracturing fluid contains proppants, which are well-sorted small particles that are added to the fluid to maintain the fracture open once the pumping is stopped and pressure is released. This allows one to create a high conductivity drain in the formation. Examples of these particles include sand grains and ceramic grains. At the end of the treatment, it is expected to obtain a fracture at least partially packed with proppants. The production of the hydrocarbons will then occur through the proppant pack. The hydraulic conductivity of the fracture is given by the proppant pack permeability and the retained fracture width. Hydraulic fracturing has been successfully applied in very low permeability gas saturated formations (often called unconventional gas reservoirs). These formations include tight-gas sandstones, coal bed methane, and gas shales. While the permeability of tight-gas sandstones is of the order of hundreds of microDarcy, gas shale permeability is of the order of hundreds of nanoDarcies.
Gas shale reservoirs are a special class of clastic reservoirs because they are a complete petroleum system in themselves. They provide the source, the reservoir, and also the seal. However, the depositional environment results in very low rock permeability, usually in the hundreds of nanoDarcy range. The trapped gas cannot easily flow to the wellbore without hydraulic fracturing. Therefore, one current practice to define shale productive reservoirs, as a consequence of hydraulic fracturing, is to map the fractured volume by studying the microseismic energy released by the stimulation process. One example of the stimulation process involves the injection of a fracturing fluid pumped at a very high pressure resulting in the initiation of a fracture zone that is thought to have propagated normal to the far-field least compressive stress. The fracturing fluid (e.g., slick water) is a slurry of well-sorted sand particles of a specified mesh that is pumped to prop the fractures opened. It is this propped volume that defines the estimated stimulated volume (ESV), calculated from microseismic analysis. Current practice is to assume that the ESV from microseismic monitoring has been propped by the fracturing process and represents a good approximation of the reservoir volume being drained.
Because of the localized nature of the reservoir, static reservoir modeling and simulation is rarely done. One practice sometimes used is to divide the reservoir into several (e.g., three) distinct zones with distinct permeability regimes. The reservoir furthest from the wellbore is considered to be the rock least affected by the stimulation process. Hence, the permeability is extremely low, in the 100 nD range. Closer to the wellbore is a zone of relatively higher permeability, in the 1000 nD range. This zone is thought to be impacted by the stimulation process and consists of a network of complex fractures. Still closer to the wellbore is the highest permeability conductive zone. An alternative to this partition is to add a high conductivity zone which represents the hydraulic fracture and which starts from the wellbore and ends at the end of the zone of relatively higher permeability.
Another commonly used reservoir characterization methodology is to study production data. Decline curves from production data are usually the mainstay of booking reserves. Seismic data are used frequently but are restricted to mapping the stacked data for hazard mitigation by locating features such as faults and karst features. Another use of seismic is to map the zones of maximum and minimum curvature to qualitatively or quantitatively study the density and orientation of fracture swarms.